Some hydrocarbon formations accessed by wellbores do not have adequate natural pressure to cause the hydrocarbons to rise to the surface on their own. In these wells, artificial lift systems can encourage production for such formations. For example, pumps used in the wellbore or at the well's surface can produce fluids to the surface, or gas injection into the wellbore can lighten the weight of fluids and facilitate their movement towards the surface.
In other techniques, a compressible fluid, such as pressurized steam, is injected into the wellbore or an adjacent wellbore to improve production. This is especially useful in a producing field having formations with heavy oil because the heat and pressure of the injected steam reduces the viscosity of oil.
To perform steam injection, operators isolate zones of interest at different depths in the wellbore with packers and then inject steam into the wellbore to the zones. Because each wellbore includes production zones with varying natural pressures and permeability, the amount of injected steam can vary between zones.
Although separate conduits can be used between the injection source and each zone, operators preferably use a single toolstring to carry the steam to the multiple zones. For example, FIG. 1 shows a section of a wellbore 10 having steam injection mandrels 50 according to the prior art disposed on a toolstring 20 downhole. Perforated areas of the wellbore 10 correspond to the zones to be injected with steam.
The mandrels 50 have one or more nozzles 60 that inject steam from the tubing string 20 to the zones of interest. Packers 26 isolate each zone to ensure that steam leaving the mandrel's nozzles 60 travels thorough the adjacent perforations 14 in the casing 12 to the desired zones. At the surface, surface equipment 30 controls injection pressures, injection rates, and steam quality during the steam injection operations.
FIG. 2 shows an isolated view of a prior art steam injection tool 50. This tool 50 is similar to that used in the “SteamSaver Injection System” available from the Assignee of the present disclosure. Additionally, this tool 50 is similar to the steam injection tool disclosed in commonly owned U.S. Pat. No. 6,708,763, which is incorporated herein by reference in its entirety.
The tool 50 has a tubular body 52 with apertures 54 for passage of steam. A sleeve 56 disposed on the body 52 contains the steam, which is directed to nozzles 60 on the end of the sleeve 56. Each nozzle 60 injects a predetermined amount of the steam into the wellbore, and this amount is determined in part by the supply pressure at the surface and the characteristics of the nozzles 60. An extension 70 conveys additional steam not passing through the apertures 54 further downhole from the tool 50 to other tools on the toolstring (20; FIG. 1). A diverter 72 can be disposed on this extension 70 to divert the steam exiting the nozzles 60.
Once the wellbore 10 of FIG. 1 is treated with steam using a tool 50 as in FIG. 2, the toolstring 20 is removed so a separate production string (not shown) can be run downhole to obtain production fluids. As will be appreciated, removing one toolstring and deploying another is a time consuming and expensive process. Rather than pulling the toolstring 20 and steam injection tools 50, it would be helpful if wellbore fluid could be produced with the existing toolstring in the wellbore. Unfortunately, producing fluids through a steam injection toolstring 20 with these prior art tools 50 has not been possible due to a number of problems and limitations, such as clogging, loss of steam quality, and poor production flow.
The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.